Well De-Liquefying System and Method

ABSTRACT

De-liquefying a well includes a steady state de-liquefying cycle which includes an initial step of pressurising the gas with a compressor. In an example embodiment, gas is delivered into the well down an outer tube. The gas displaces liquid within the well by pushing the liquid within tubes up another tube, as a liquid slug, to the surface. A sensor operates to sense the arrival of the liquid. A controller interrogates the sensor to determine whether a slug of liquid has arrived. If not, gas is continued to be delivered into the well. When the controller determines via the sensor that a slug of liquid has arrived, the controller operates to shut the delivery of gas to the well. This may be done either immediately upon detection of the slug or at some predetermined delay thereafter. To shut down the delivery of gas to the well, the controller opens a valve (in the event it was shut) to allow the compressor to discharge to a sales line. The controller also closes a valve and opens another valve to relieve pressure within the outer tube to the separator pressure. The controller then idles for a prescribed time delay before recommencing the cycle.

FIELD

The present invention relates to the de-liquefying of vertical andhorizontal gas wells.

BACKGROUND

Liquid loading is a phenomenon where liquid accumulates at the bottom ofa gas well. This limits and can ultimately prevent the well fromproducing gas at a commercially viable rate and in any event at a ratethat would normally be possible if the liquid were not present.

The liquid accumulating at the bottom of the well may be water or oil,or a combination of both. Often, initially, the bottom hole pressure(BHP) of a well when first commissioned is sufficiently high so that uphole gas velocity would be sufficient to either carry liquid in the wellto the surface, or at least will be sufficient to enable the gas to passthrough the liquid to the surface at a reduced rate. The required gasvelocity for this complete conveyance of liquid to the surface to occuris generally agreed to be in the order of 3 m (10 feet) per second orgreater.

As a gas well loses BHP it will also lose up hole gas velocity, whichoften results in liquid loading of the well. Liquid that is not conveyedto the surface will build up in the well over time.

The liquid loading is also at times exacerbated by the very procedurerequired to initially construct and develop the gas well. This mayparticularly be the case for gas wells drilled in tight shaleformations. These formations have a minimal porosity but still containlarge volumes of gas. In order to release the gas, it is necessary toincrease the permeability of the shale. One process for achieving thisis hydraulic fracturing. Hydraulic fracturing involves pumping a slurryof water (“frac water”) and sand (“frac sand”) into the formation atsufficient pressure to fracture the rock. The sand assists in holdingthe fractures or cracks open after fracturing, allowing the gas to morereadily migrate to the well bore. A significant percentage of the fracwater will be produced back from the well formation in the initialstages of well development. However the remaining frac water will beheld in the formation and produced over time, for example several years,as flow to the well bore. Frac water will also often carry frac sandinto the well. The presence of the frac sand makes the frac waterdifficult to handle with conventional pumps.

It is typical to produce the gas directly up the well casing ifpossible, but generally very early in the life of a gas well a “velocitystring” is installed inside the well casing to reduce the diameter thegas is being produced up and therefore increasing the up hole velocity.In this way liquid can be carried up with the produced gas for a longerterm before liquid loading is experienced.

Once liquid loading begins, in some wells, an operator may have onlyrecovered a small proportion of the gas in reserve, which could be aslittle as 10% or less of the total gas reserves present. At this point,some form of action is required to lift the liquid to the surface so thewell can continue to produce gas at a commercially viable rate.

If the right set of circumstances exists, and where liquid loading isonly marginal, the addition of foaming chemicals to the well will allowthe available BHP to carry small amounts of liquid to the surface asthey foam. This technique is often used because it is easy to implement.However is rarely effective for the long term and is also reliant on BHPto a reduced degree.

A further option available is to employ a method called “plunger lift”.This is a method which utilizes the available BHP to carry the liquid tothe surface without needing an up hole gas velocity as high as 3 m (10feet) per second. The plunger used in this method is in the form of aloose fitting plug, generally made of metal and about 500 mm long. Whenthe gas well is in production the up hole velocity is typicallysufficient to hold the plunger at the top of the production string. Whenthe gas well is shut in, and production gas flow from the well stops,the plunger falls to the bottom of the production tubing. Given adequatetime, it will eventually sink through the liquid and sit on a stoplocated at the bottom of the production tube.

After a predetermined period of time has elapsed, the well is put backinto production. The gas pressure above the liquid in the productiontubing falls away and the available BHP pushes the plunger to thesurface with a slug of liquid riding above it. In the absence of aplunger in the tubing, the up hole velocity would not be sufficient tocarry the slug up the tubing in a single body without the slug breakingup and falling back past the up flowing gas.

With a plunger in the tubing, only a very small insignificant volume ofliquid is able to flow back past the plunger as the gas pressure istrying to push up past the plunger. Accordingly this system works wellif there is adequate BHP and all other requirements are satisfied.Naturally, this Plunger lift method also relies on gravity to get theplunger to the bottom of the well. Thus this method is not viable inwells which extend beyond 30° from the vertical. De-liquefying ofhorizontal wells is a more pressing and important problem that requiresa solution over vertical wells, therefore plunger lift fails to addressthis horizontal well problem.

Plunger lift and foaming are useful as they are relatively in expensiveand do not rely on external energy other than the wells own BHP.

At some point the above methods that do not rely on any source ofexternal energy other than BHP will not be effective due to reduced BHPand the options at that stage are to either re frac the well in the hopeof increasing BHP or, use some form of artificial lift system on thewell to remove the liquid. Conventional artificial lift systems includesucker rod pumps, progressive cavity pumps, hydraulically operated downhole pumps and electrical submersible pumps.

However the reliability of these pumping methods operating in thedifficult environment of a gas well is so poor that a large number ofpotentially high producing wells are simply shut in awaiting a moreeffective technology for deliquefying these wells.

A further significant factor in optimizing gas production is the amountof pressure the well head is subjected to. In a typical gas well, thewell casing, or velocity string if installed, is connected at the wellhead via a gathering line to a separator. The separator separates gasfrom liquid carried in the gas. The gas is then able to flow from theseparator through a valve to a sales line. The sales line carries gasaway from the well site for further processing and sale. Ideally the gasin the sales line is at a high pressure in order to effectivelytransport the gas to the further processing site. However if the salesgas line pressure is too high, for example 300 psi or greater, then theBHP of the well is required to push against this pressure as well as thepressure of the liquid in the hole. To provide context, a gas well headpressure of 300 psi will have the same detrimental effect on gasproduction on a well as a 660 ft column of liquid standing in the well.Therefore well head compression is often implemented to lower the wellhead pressure by drawing gas from the well with a gas compressor andforcing it down the sales lines. By reducing the gas pressure at thewell head the up hole gas velocity is greatly increased and the affectsof reduced BHP on the liquid loading problem can be minimised.

A gas well may have liquid in it for a number of reasons. It may be as aresult of liquid loading or it may be that liquid was added to the welldeliberately to “Kill” the well to work on it. If enough liquid of thenecessary SG weight is added to a well it will completely prevent thewell from producing gas at all making it safe to work on. After workingon the well it is often necessary to “Kick the well off”. One way thatthis is done and specifically when the well is fitted with a velocitystring is to use a large high pressure gas compressor to blow highpressure gas down the well casing or “back side”. The effect of this isto push liquid down the casing and up the velocity string to theseparator. As there are no check valves involved in this conventionalprocess much of the liquid is pushed back into the formation were itcame from. This type of compressor is often mounted on a truck anddriven to site when needed. Additionally frequently the gas used in thisprocess is nitrogen, requiring the need to also hire a Nitrogengenerator. Further due to the high pressures involved (e.g. over5000PSI) additional safe precautions are required during this procedure.Naturally therefore this kick off process can not be used as a deliquefying method on an ongoing basis as gas production can not bemaintained throughout the process and the size and pressure rating ofthe compressor required is much too large and expensive.

The present invention has arisen through a desire to provide analternate mechanism for deliquefying a gas well.

SUMMARY

The present invention combines the benefits of well head compression anduse of this same well head compressor to provide power to operate adeliquefying mechanism. A gas well that is completely emptied of fluidand has the lowest possible well head pressure will be producing at itsmaximum potential and operate economically for the longest life. Themechanism will combine the existing techniques developed to kick of awell with compressed gas with the use of a second inner string down thewell and a check valve assembly so as to isolate this displacement zonefrom the producing well casing.

An example method of the present invention comprises de-liquefying a gaswell provided with a well casing in fluid communication with a separatorinto which gas from the well flows, the method comprising:

-   -   delivering pressurised gas from the separator back into the well        to displace liquid in the well to a location outside of the        well.

The example method may comprise directing the liquid lifted from thewell together with the gas used in lifting the liquid from the well tothe separator.

The example method may comprise pressurising the gas from the separatorwhich is delivered back into the well to a pressure sufficient toachieve a gas flow rate up the well of at least 3 m (10 feet) per secondwhile carrying a slug of liquid.

The example method may comprise sensing when liquid lifted from the wellreaches the location outside of the well; and, ceasing delivery of thegas from the separator back into the well at a selectable time aftersensing the liquid reaching the location.

The example method may comprise, upon expiration of the selectable timeperiod, relieving pressure of the gas to the separator pressure.

The example method may comprise performing a de-liquefying cyclecomprising delivering gas from the separator into the well; ceasingdelivery of gas at the selected time after sensing the liquid reachingthe location, and relieving pressure of the gas to separator pressure.

The example method may comprise measuring a time period between deliveryof gas back into the well from the separator and the liquid reaching thelocation; and,

-   -   using an adaptive algorithm to control a cycle rate of the        deliquefying cycle on the basis of historical data relating to        the measured time period.

The example method may comprise performing a start up procedure oninitial use of the method, the start up procedure comprising:

-   -   forming a closed gas circuit between the well casing and the        separator, and continuously circulating gas from the well to the        well separator and back to the well for a selectable minimum        time period.

The minimum time period may be between 5 minutes to 30 minutes.

The example method may comprise after performing the start up procedure,operating the method in a start up mode wherein during an initial numberof deliquefying cycles after the start up procedure pressure of gasbeing delivered from the separator to the well is not relieved to wellhead pressure.

The initial number of cycles may be between 5 to 15 cycles.

The example method may comprise providing a return path for thedelivered gas into and out of the well, wherein the return path isisolated from a production gas flow path from the well casing to theseparator, the return path being arranged to allow one way flow ofliquid residing in the well into the return path.

Providing the return path may comprise:

-   -   installing an outer tube in the well casing;    -   installing an inner tube in the outer tube to create a first leg        of the return flow path between the inner tube and the outer        tube, wherein an inside of the inner tube forms a second leg of        the return path; and,    -   providing a one way valve allowing flow of liquid in a direction        from the well casing into the outer tube.

The example method may comprise coupling a well head end of the innertube to the separator.

The example method may comprise coupling a well head end of the outertube to the separator.

The example method may comprise coupling a compressor between theseparator and the well head end of the outer tube.

The example method may comprise providing a valved pressure relief pathbetween the separator and the outer tube, the valved pressure reliefpath when opened, enabling pressure relief of the gas being deliveredfrom the compressor to the well to be relieved to separator pressure.

Another example method of the present invention comprises de-liquefyinga gas well provided with a well casing in fluid communication with aseparator into which gas from the well flows, the method comprising:

-   -   installing an outer tube in the well casing;    -   installing an inner tube in the outer tube to create a first        flow path between the inner tube and the outer tube and wherein        fluid in the first flow path can flow into the inner tube;    -   enabling the inner tube to be in fluid communication with a        fluid collector at a location outside of the well;    -   providing a one way valve allowing flow of liquid in a direction        from the well casing into the outer tube; and,    -   pressurising gas sourced from the well and delivering the        pressurised gas back to the well through the outer tube.

Enabling the inner tube to be in fluid communication with a fluidcollector at a location outside of the well may comprise: arranging theinner tube to be in fluid communication with the separator whereinliquid and gas flowing through the inner tube is directed to flow intothe separator.

The example method may comprise ceasing delivery of the pressurised gasupon in response to detecting presence of the liquid at a know locationin the inner tube.

The example method may comprise venting the outer tube and the innertube to the separator subsequent to detecting the presence of theliquid.

The venting may be performed at selectable time periods subsequent todetecting the presence of the liquid.

The example method may comprise using gas pressurised by a well headcompressor of the well as the pressurised gas being delivered back intothe well.

The example method may comprise:

-   -   designating the steps of: delivering gas from the separator into        the well; ceasing delivery of gas; and, relieving pressure of        the gas to separator pressure, as a de-liquefying cycle;    -   measuring a time period between delivery of gas back into the        well from the separator and the liquid reaching the location;        and,    -   using an adaptive algorithm to control a cycle rate of the        de-liquefying cycle on the basis of historical data relating to        the measured time period.

In a further example embodiment of the invention, a de-liquefying systemis provided for a gas well having a well casing in fluid communicationwith a separator, the system comprising:

-   -   a fluid flow path extending from the separator down the well        casing, up the well and to a location outside of the gas well;        and,    -   a one way valve in the fluid flow path capable of allowing fluid        flow only in a direction from the well casing into the fluid        flow path, wherein pressurised gas from the separator is        delivered to the well and is capable of displacing liquid in the        well up the fluid flow path to the location.

The fluid flow path may comprise an outer tube extending down the welland being in fluid communication with the separator at a well head endand provided with the one way valve at a down hole end, and an innertube suspended in the outer tube and having a down hole end above theone way valve and an opposite well head end in fluid communication withthe separator, wherein pressurised gas from the separator flows down theouter tube and displaces liquid in the outer tube and inner tube up theinner tube to the separator.

The de-liquefying system may comprise a controller capable of cyclicallycontrolling delivery of pressurised gas to the fluid flow path.

The controller may operate an adaptive algorithm to vary a rate ofcyclically delivering pressurised gas on a basis of a plurality ofmeasured times between delivery of pressurised gas and liquid displacedby the gas reaching the location.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of standard production equipmentfor a gas well;

FIG. 2 is a graph representing gas production from a gas well;

FIG. 3 is a schematic representation of a system for de-liquefying awell in accordance with an embodiment of the present invention;

FIG. 4 is a flow chart representing steps in a de-liquefying cycle in anembodiment of a method for de-liquefying a gas well; and,

FIG. 5 illustrates an embodiment of a method for de-liquefying a gaswell.

DETAILED DESCRIPTION

FIG. 1 illustrates a typical well head arrangement for a gas well W. Thegas well W is lined with a well casing 10 which is typically cemented inplace and later perforated through which production gas flows to thesurface. At the well head 12, the well casing 10 is coupled by agathering line 14 to a separator 16. Isolation valve 18 is placed in thegathering line 14 together with one way valves 22 and 24 which prevent aflow of gas from separator 16 to the well casing 10. Separator 16operates to separate production gas from liquid which may be lifted bythe gas to the well head 12. The separator has a liquid outlet 26through which liquid 28, separated from the gas in the separator 16 byaction of gravity, flows to discharge conduit 30 due to the pressurewithin the separator. A gas outlet 32 of the separator 16 may be coupledby conduit 34 a to a gas compressor 36 if the particular well is alreadyfitted with well head compression. Gas compressor 36 in turn is coupledby conduit 34 b to a sales line 38 via a valve 40. Gas compressor 36draws gas from separator 26, which has the effect of reducing well headpressure, pressurises the gas and delivers the pressurised gas to salesline 38. The gas is pressurised in order to provide sufficient gaspressure for the gas flow along the sales line 38 to a remote storagefacility or processing plant. In a typical operational scenario, gaspressure within separator 16 may be in the order of 20 PSI with wellhead compression fitted whereas gas discharged from a high pressure side58 of compressor 36 for delivery to sales line 38 can be from 50 to1,500 PSI. Compressor 36 requires a pumping capacity at least equal tothe production capability of the well, for example 600 MCF/D. It is alsoknown to have a well head compressor 36 servicing more than one gas wellin which event the compressor FAD is scaled up accordingly.

Hypothetically initial BHP for the well W may be in the order of3000-4000 PSI. This will ordinarily result in a gas up hole velocitywell in excess of 3 m (ten feet) per second in which case liquid loadingis not an issue. A substantial drop in BHP in a relatively short timeperiod is common. For example, the BHP may drop to say 1000 PSI withinthree months or a few years. Thereafter, BHP will progressively decreasein time. In this initial phase of the well life it is not unusual toproduce 1000 MCF of gas per day. However, as the BHP reduces, theability of the gas to lift liquid from the well to de-liquefy the wellreduces.

The onset of liquid loading can often be seen by tracking gas productionfrom a well.

FIG. 2 illustrates an example of a gas production curve showing theeffects of liquid loading. For a period from T0-T1 gas production isrelatively high with BHP being sufficient to result in a gas velocityof >3 m (10 feet) per second. At T1 at which time BHP has reduced to alevel where liquid loading commences, the gas production curve commencesto oscillate. Initially there is a relatively quick drop in productionto point a on the curve as liquid fills the well. The BHP may then buildsufficiently over time and experience a short term recovery and increaseup hole velocity to a level where the liquid can be blown from the holeresulting in a brief increase in gas production to point b on the curve.Subsequently BHP again falls and as liquid again builds in the wellthere is a relatively quick drop in production to point c on the curve.This cycle continues until the time T2 where the well is now liquidloaded to the extent that a column of liquid in the well W is built to aheight such that the pressure exerted by the column is equal to thewells BHP so that the gas can no longer push its way into the well andgas production ceases.

Of all the various techniques described above for attempting tode-liquefy a gas well it is the installation of a velocity string whichis generally the first to be used. FIG. 1 illustrates a velocity string42 extending into the well. A velocity string is a smaller diameterproduction tube suspended in the well so that the diameter is reducedthereby increasing the up hole gas velocity. The use of the velocitystring increases up hole friction and therefore can slightly reduceproduction although usually this is inconsequential in comparison toliquid loading. Depending on the well, a velocity string may alleviateliquid loading for a few months or even a number of years. Howevereventually the well will lose BHP to liquid load again.

FIG. 3 illustrates a system 50 which facilitates an embodiment of amethod of de-liquefying a well W. In FIG. 3 features having the same orsimilar construction and/or operation to those depicted in FIG. 1 aredenoted by the same reference numbers. The system 50 can be retrofittedor plumbed to an existing well head construction. In particular FIG. 3illustrates the system 50 coupled to a well casing 10, gathering line14, separator 16, and gas compressor 36. When the gas compressor 36 isused to service multiple wells it should have a FAD equivalent to thetotal production from all wells serviced plus an amount calculated to benecessary to operate the proposed method. Typically this additionalcapacity is expected to be from 5 to 15%. The system 50 includes anouter tube 52 that is suspended in the well casing 10. In the event thata velocity string 42 was already in place, the velocity string 42 withminor modification can be use as the outer tube 52. This modificationbeing the fitting of a seating nipple at the down hole end which willinvolve the removal and subsequent re installment of the velocity string42.

The outer tube 52 has an outer diameter substantially smaller than theinner diameter of well casing 10. For example outer tube 52 may comprisea standard 2⅜″ API EUE tubing provided with a standard 2⅜″ seatingnipple at the bottom, while the well casing may have a diameter of 4.5″.The outer tube 52 is tied off at the well head 12 as it would have beenwhen used as a velocity string. A check valve (i.e. one way valve) 54 isprovided at a down hole end of outer tube 52. The valve 54 enables aflow of liquid in a direction from the well into the outer tube 52 butprevents a reverse flow of liquid. The down hole end of tube 52, isdisposed: for a vertical well, below the level of a lower mostperforation in well casing 10; or, for a horizontal well, to the pointof lowest true depth. A well head end of a tube 52 is plumbed viaconduit 56 to a high pressure side 58 of gas compressor 36. Conduit 56is plumbed to conduit 34 b between the high pressure end 58 of gascompressor 36 and valve 40 in the sales line 38. A further conduit 60extends between conduit 56 and a point on gather line 14 between valves18 and 22. Valve 62 is placed in conduit 60 to selectively open andclose fluid communication between conduits 56 and gather line 14 throughthe conduit 60. A further valve 64 is placed in conduit 56 upstream ofconduit 60. Conduit 56 also has installed in it a pressure transducer 66upstream of valve 64, and may have a gas meter 68 upstream of thepressure transducer 66.

Pressure transducer 66 operates to provide an indication of gas pressurewithin conduit 56 to a controller such as a computer or a PLC. Thecontroller is programmed to not commence a de-liquefying cycle in theevent that pressure of the gas within conduit 56 is below a thresholdlevel.

Gas meter 68 if provided operates to measure the volume of gas deliveredback to the well. Gas meter 68 may typically be used where the system 50is operating on a number of wells and provides a mechanism for meteringthe volume of gas delivered back to each well for production recordkeeping purposes only, as gas produced from one well may be used to deliquefy a different well. As the gas used to de liquefy the well willultimately look like gas production from that well it is important froman accounting point of view to know how much gas is really produced fromeach well.

The system 50 also incorporates an inner tube 70 which passes throughthe outer tube 52 and is suspended so that a down hole end 72 is locatedslightly above a down hole end of outer tube 52. Inner tube 70 may havean outer diameter of about 1.5″. As a consequence a generally annularflow path is created between the outer tube 52 and inner tube 70. A wellhead end 74 of inner tube 70 is connected to gathering line 14 betweenone way valve 22 and valve 24. Liquid sensor 76 is coupled with ahorizontal portion 78 of inner tube 70 and operates to sense thepresence of liquid in the inner tube 70. Valve 80 is also placed in thehorizontal portion 78 of inner tube 70 upstream of liquid sensor 76.

The valves 18, 65 and 80 form an isolation valve set 82 which duringnormal operation of system 50 are open to allow fluid flow. Theisolation valve set 82 can be manually operated however to isolate thewell W from equipment down stream of the well head for maintenancepurposes or in emergency situations.

A pressure transducer 84 is also coupled with gathering line 14downstream of valve 18 and upstream of the location where conduit 60joins gathering line 14. The pressure transducer 84 measures gaspressure in the gathering line 14 and communicates this to thecontroller. The controller is programmed to not attempt to operate thesystem 50 to de-liquefy the well if the measured gathering line pressureis above a certain threshold. This pressure would be typically around 50PSI

In normal operating conditions of system 50, valve set 82 will always beopen. Initially all valves will be found in their “Shut In” positions.Valve 62 will start in the open position, valve 64 would be shut, valve20 would be shut and valve 40 would be open.

For the purposes of this description of system 50, we are assuming thatthis particular well no longer has enough BHP to achieve an up holevelocity of 3 m (10 feet) per second, either up the casing or up avelocity string, otherwise the operator would not have a liquid loadingproblem to contend with. We are also in this example making theassumption that the system has been recently operated and has been “shutin” in accordance with the proper procedure therefore there is not therequirement for a high pressure kick off described previously.

Firstly valve 62 would be closed by the PLC to maintain as much pressureas possible in the riser pipe 52. Valve 20 is opened to allow gas fromthe well casing 10 to flow through conduit 14 to the separator 16.Initially there should not be any liquid carried in this gas but ifthere was the liquid 28 is separated from the gas and is discharged viaoutlet 26 and conduit 30. The gas flows through outlet 32 throughconduit 34 to the gas compressor 36. Gas is now compressed anddischarged at high pressure side 58 and flows through conduit 34 b andopen valve 40 to the sales line 38.

Gas within the conduit 56 is also pressurised to the same pressure asthe gas and sales line 38. However this gas isn't able to flow to thewell by virtue of valve 64 being shut. In addition, the pressuretransducer 66 provides a signal to the controller indicative of the gaspressure within conduit 56. The controller is programmed to shut valve64 (in the event that it was not previously shut) and more importantlynot initiate a pumping cycle when gas pressure in line 56 is sensed asbeing lower than that expected to be delivered back into the well forde-liquefying purposes. For example, for the well at hand, if initialcalculations show a gas pressure of between 300-400 PSI would ordinarilybe required during a de-liquefying cycle, the controller may beprogrammed to automatically shut valve 64 or not initiate a cycle if gaspressure sensed by sensor 66 in conduit 56 is say under 500 Psi.

In describing operation of system 50, assume that well W is liquidloading, but not liquid loaded. Liquid is at a level L in the well W.Liquid is thus at the same level inside of outer tube 52 and on theinside of inner tube 70. The tubes 52 and 70 form a return flow path 90comprising a first leg 92 (shown with double arrows) formed by asubstantially annular space between outer tube 52 and inner tube 70, anda second leg 94 (shown by triple arrows) being a return leg up theinside of inner tube 70. Thus, assuming the appropriate state orposition of the valves, fluid is able to flow through conduit 56 downfirst leg 92 between tube 52 and tube 70, back up tube 70 and into thegathering line 14.

Liquid is at level L in the well W and within the tubes 52 and 70. Ade-liquefying cycle of system 50 comprises delivering pressurised gasfrom the separator 16 back into the well W to lift liquid in the well toa location outside of the well. For the gas compressor 36 to be able toachieve sufficient pressure to overcome the static weight of thevertical column of fluid in the inner tube 94 it may be necessary toclose gas valve 40 to the sales line otherwise the maximum pressureattainable will be equivalent to sales line pressure only. Though notoften required the compressor will often have a top pressure rating of1,500 to 2,500 PSI.

Pressurised gas, which was initially sourced from the well W, is beingdelivered back into the well through conduit 56 down the first leg 92.The gas pressure acts on the surface of liquid L within the outer tube52 forcing the liquid down outer tube 52 to flow up the inner tube 70(i.e. up the second leg 94). The liquid cannot re-enter the well W byaction of the valve 54. As the gas continues to act it forcessubstantially all of the liquid within the inner tube 70 creating aliquid slug, and the gas follows the liquid slug up the inner tube 70.The liquid eventually reaches a location outside the well where it issensed by sensor 76 within horizontal section 78. The liquid, togetherwith the following gas flows into gathering line 14, valve 20 and oneway valve 24, into the separator 16. Also, upon sensing the presence ofliquid in the horizontal section 78, the controller closes valve 64 toprevent any more compressed gas to be used for that cycle, opens valve40 (in the event it was closed) to allow gas from the compressor toreturn to the sales line and opens valve 62 to relieve pressure withinconduit 56 to separator pressure at the well head, i.e. pressure withingathering line 14 and separator 16. Thus pressure is equalised betweenouter tube 52, gathering line 14 and separator 16. This also relievespressure on valve 54 allowing liquid from well W to flow into tubes 52and 70. Depending on the circumstances at hand, valves 40, 64 and 62 maybe operated to close and open immediately upon detecting of liquid bythe sensor 76, or may be closed and opened at a selectable time delaythereafter.

This completes one de-liquefying cycle of system 50.

The cycle can be continuously repeated at set or variable periods. Forexample this cycle may be repeated once every hour. The volume andpressure of gas delivered per cycle is determined to provide an up holegas velocity in the order of 3 m (10 feet) per second in order to liftliquid within the well to the surface. During each cycle, the controllerby virtue of operation of sensor 76 is also able to determine the lengthof time that the sensor senses liquid, i.e. the length of time thesensor is wet. As the inner diameter of inner tube 70 is known, and thevelocity of the liquid is known (or assumed at 3 m (10 feet) per second)the controller can determine the approximate volume of liquid lifted percycle. The controller may be provided with a self learning or adaptivealgorithm to vary the cycle period on the basis of a running average ofliquid volumes over a previous number of cycles. For example if a cycleis initially performed at periods or intervals of one hour, but thecontroller determines that the sensor 76 is wet for increasing lengthsof time per cycle, which is indicative of liquid loading occurring at agreater rate, the cycle period may be reduced to say 59 minutes.Alternately, if it is determined that the sensor 76 is staying wet forsuccessive shorter periods of time per cycle then the cycle period maybe extended to say one hour and one minute. However, maintaining aquicker cycle period than may be strictly necessary does not create anysubstantive burden or difficulty as the gas delivered to the well percycle is simply returned each cycle. There is a marginal increase inenergy use due to the need to operate compressor 36 to deliver the gasinto the well. However this is inconsequential to the overall viabilityof the well.

It is important to note that this system 50 is not a conventional “GasLifting” system. Unlike conventional gas lifting, System 50 is notreliant on the presence of gas mixed with liquid, changing the specificgravity of that liquid to make it possible for the wells bottom holepressure to “gas lift” the fluid to the surface. It would be possiblefor an embodiment of system 50 to operate with no BHP in the well atall. By devising a system where we have one tube within another tubewithin the well casing it is possible for system 50 to effectivelycreate its own BHP environment. This system 50 could be best describedas “Slug Lift”.

A slug of liquid is formed by forcing gas down tubing 70 until thedisplacement gas has forced the top of the liquid all the way down tothe bottom of tube 70. As the liquid is forced down the annular flowpath 92 by gas pressure the liquid is displaced into and raised upinside tube 94. Once all the liquid has been forced up inside tube 70the pressure required will not continue to rise any further. Thepressure that is required to raise this slug further up tube 70 is aresult of a calculation of the SG of the liquid multiplied by the totalheight of the liquid slug inside the inner tube 94 plus any pressurethat is operating against the top of the slug caused by well head andseparator back pressure. Additional to this static pressure an allowancehas to be made for friction loss acting on the liquid slug in tube 70.

The gas then proceeds to follow the slug of liquid up tube 70. The rateof travel of this slug of liquid up the inner tubing 70 is required tobe 3 m (10 feet) per second or greater to ensure that the slug continuesto maintain upward travel without falling back. The calculation of thevolume of gas required to maintain this 3 m (10 feet) per second up holevelocity of the liquid slug is complex but is primarily the operatingpressure multiplied by the volume of 3 m (10 feet) of the tube 70.

FIG. 4 depicts in the form of a flow chart a method 100 of de-liquefyinga well W using system 50. The method 100 comprises a steady statede-liquefying cycle 101 which has an initial step 102 of pressurisingthe gas (by use of compressor 36). This gas is then at step 104delivered into the well W down leg 92 (i.e. tube 52) of the return path90. The gas displaces liquid within the well W by in effect pushing theliquid within tubes 52 and 70 up tube 70 to the surface. At step 106 inthe method, sensor 76 operates to sense the arrival of the liquid. Atstep 108 the controller interrogates sensor 76 to determine whether ornot a slug of liquid has arrived. If not, gas is continued to bedelivered into the well and the method returns to step 104. However whenthe controller determines via sensor 76 that a slug of liquid hasarrived, the controller at step 110 operates to shut the delivery of gasto the well W. This may be done either immediately upon detecting of theslug or at some predetermined delay thereafter. To shut down thedelivery of gas to the well W the controller opens valve 40 (in theevent it was shut) to allow the compressor 36 to discharge to the salesline 38. Simultaneously, at step 112 the controller closes valve 64 andopens valve 62 to relieve pressure within the outer tube 52 to theseparator pressure. The controller then idles for a prescribed timedelay 114 before recommencing the cycle.

The steps of method 100 depicted in FIG. 4 together represent the steadystate de-liquefying cycle of operation of system 50.

With reference to FIG. 5, it is also seen however that method 100incorporates an initial start up sequence or procedure 120 andsubsequently performs a number of start up cycles 122 prior to enteringthe steady state de-liquefying cycle 101. In start up procedure 120valve 40 is shut, valve 62 is shut, valve 64 is open, valve 20 is openand the valve set 82 is open. Compressor 36 is operated to deliver gasfrom separator 16 through outer tube 52 into the well W. The delivery ofgas is maintained for an extended period of time for the purposes ofessentially blowing out the liquid within the outer tube 52 and innertube 70. At this time the system is performing a conventional “gas lift”function as the well has been shut in and probably has sufficient liquidwithin the well for a conventional gas lift to work for a short time. Itis thought that this cycle may take between five to thirty minutes. Thestart up procedure can be terminated when sensor 76, after initiallydetecting presence of the liquid, subsequently detects the occasionalpresence of a liquid.

After the start up procedure 120, system 50 enters or commences a numberof start up cycles 122. Typically between 5 to 10 start up cycles mayendure prior to the method 100 moving to the steady state de-liquefyingcycles 101. The start up cycles 122 operate in the same manner as steadystate cycle 101 with the exception that step 112 being the pressurerelief/equalisation step is bypassed. In practice this means that thevalve 62 is maintained closed for the start up cycles. The purpose ofthis is to maintain pressure within the outer tube 52 resulting in lessliquid entering this space from the well through check valve 54resulting in a shorter slug height and subsequently reduced operatingpressure during start up.

During all times of operation of the system 50 and method 100, the wellW is able to produce gas via the casing 10 (assuming sufficient BHP)which then flows through gathering line 14 and into separator 16.Further, the gas pressure within outer tube 52 is isolated from the wellpressure. Thus the system 50 and method 100 does not provide anysubstantive impediment or interruption to gas production from the well.

Embodiments of the method enable liquid to be lifted from a well usinggas from the well itself as well as much of the existing infrastructure.In terms of hardware, all that is required in order to install thesystem 50 and operate method 100 is tubing of two different diameters, anumber of valves, some sensors and a controller such as a computer or aPLC.

Modifications and variations to the system and method that would beobvious to persons of ordinary skill in the art are deemed to be withinthe scope of the present invention the nature of which is to bedetermined from the above description and the appended claims.

The claims defining the invention are as follows:
 1. A method ofdeliquefying a gas well provided with a well casing in fluidcommunication with a separator into which gas from the well flows, themethod comprising: pressurising the gas from the separator; deliveringpressurised gas from the separator back into the well to lift a liquidslug in the well together with the gas used in lifting the liquid fromthe well to the separator, wherein the gas from the separator which isdelivered into the well is pressurised to a pressure sufficient toachieve a gas flow rate up the well of at least 3 m (10 feet) per secondwhile carrying a slug of liquid.
 2. The method according to claim 1,further comprising: sensing when the liquid slug lifted from the wellreaches a location outside of the well; and ceasing delivery of the gasfrom the separator back into the well at a selectable time after sensingthe liquid reaching the location.
 3. The method according to claim 2,further comprising: upon expiration of the selectable time period,relieving pressure of the gas to the separator pressure.
 4. The methodaccording to claim 3, further comprising: performing a deliquefyingcycle comprising delivering gas from the separator into the well;ceasing delivery of gas at the selected time after sensing the liquidreaching the location; and relieving pressure of the gas to separatorpressure.
 5. The method according to claim 4, further comprising:measuring a time period between delivery of gas back into the well fromthe separator and the liquid reaching the location; and using anadaptive algorithm to control a cycle rate of the deliquefying cycle onthe basis of historical data relating to the measured time period. 6.The method according claim 5, further comprising: performing a start upprocedure on initial use of the method, the start up procedurecomprising forming a closed gas circuit between the well casing and theseparator, and continuously circulating gas from the well to the wellseparator and back to the well for a selectable minimum time period. 7.The method according to claim 6, wherein the minimum time period isbetween 5 minutes to 30 minutes.
 8. The method according to claim 7,further comprising: after performing the start up procedure, operatingthe method in a start up mode wherein during an initial number ofdeliquefying cycles after the start up procedure pressure of gas beingdelivered from the compressor to the well is not relieved to seperatorpressure.
 9. The method according to claim 8, wherein the initial numberof cycles is between 5 to 15 cycles.
 10. The method according to claim6, further comprising: providing a return path for the delivered gasinto and out of the well, wherein the return path is isolated from aproduction gas flow path from the well casing to the separator, thereturn path being arranged to allow one way flow of liquid residing inthe well into the return path, wherein providing the return pathcomprises: installing an outer tube in the well casing; installing aninner tube in the outer tube to create a first leg of the return flowpath between the inner tube and the outer tube, wherein an inside of theinner tube forms a second leg of the return path; and providing a oneway valve allowing flow of liquid in a direction from the well casinginto the outer tube.
 11. The method according to claim 10, furthercomprising: providing a valved pressure relief path between theseparator and the outer tube, wherein the valved pressure relief path,when opened, enables pressure relief of the gas being delivered from thecompressor to the well to be relieved to separator pressure.
 12. Amethod of de-liquefying a gas well provided with a well casing in fluidcommunication with a separator into which gas from the well flows, themethod comprising: installing an outer tube in the well casing;installing an inner tube in the outer tube to create a first flow pathbetween the inner tube and the outer tube and wherein fluid in the firstflow path can flow into the inner tube; enabling the inner tube to be influid communication with a fluid collector at a location outside of thewell; providing a one way valve allowing flow of liquid in a directionfrom the well casing into the outer tube; and pressurising gas sourcedfrom the well and delivering the pressurised gas back to the wellthrough the outer tube.
 13. The method according to claim 12, whereinenabling the inner tube to be in fluid communication with a fluidcollector at a location outside of the well comprises: arranging theinner tube to be in fluid communication with the separator whereinliquid and gas flowing through the inner tube is directed to flow intothe separator.
 14. The method according to claim 13, further comprising:ceasing delivery of the pressurised gas upon in response to detectingpresence of the liquid at a know location in the inner tube.
 15. Themethod according to 14, further comprising: venting the outer tube andthe inner tube to the separator subsequent to detecting the presence ofthe liquid.
 16. The method according to claim 15, further comprising:designating the steps of delivering gas from the separator into thewell, ceasing delivery of gas, and relieving pressure of the gas toseparator pressure, as a de-liquefying cycle; measuring a time periodbetween delivery of gas back into the well from the separator and theliquid reaching the location; and using an adaptive algorithm to controla cycle rate of the de-liquefying cycle on the basis of historical datarelating to the measured time period.
 17. A de-liquefying system for agas well having a well casing in fluid communication with a separator,the system comprising: a fluid flow path extending from the separatordown the well casing, up the well and to a location outside of the gaswell; and a one way valve in the fluid flow path capable of allowingfluid flow only in a direction from the well casing into the fluid flowpath, wherein pressurised gas from the separator is delivered to thewell and is capable of displacing liquid in the well up the fluid flowpath to the location.
 18. The de-liquefying system according to claim17, wherein the fluid flow path comprises: an outer tube extending downthe well and being in fluid communication with the separator at a wellhead end and provided with the one way valve at a down hole end; and aninner tube suspended in the outer tube and having a down hole end abovethe one way valve and an opposite well head end in fluid communicationwith the separator; wherein pressurised gas from the separator flowsdown the outer tube and displaces liquid in the outer tube and innertube up the inner tube to the separator.
 19. The de-liquefying systemaccording to claim 18, further comprising: a controller configured tocyclically control delivery of pressurised gas to the fluid flow path.20. The de-liquefying system according to claim 19, wherein thecontroller operates an adaptive algorithm to vary a rate of cyclicallydelivering pressurised gas on a basis of a plurality of measured timesbetween delivery of pressurised gas and liquid displaced by the gasreaching the location.